The present invention relates generally to novel cement compositions and, more specifically, to cement compositions that are suitable for the high temperature, high pressure conditions commonly found in oil and gas wells. In particular, highly resilient cement compositions having improved sealing properties are disclosed.
Cement is commonly used to seal the wellbore of oil and gas wells. The downhole conditions of wells pose extreme conditions for the cement, exposing it to high temperatures, high pressures, and variable tectonic forces. These conditions frequently lead to the formation of fractures in the concrete, and ultimately failure and collapse of the cement. This damage decreases the production of the well, and may require treatment of the well to repair or replace the cement.
Cementing is a common technique employed during many phases of wellbore operations. For example, cement may be employed to isolate or secure various casing strings and/or liners in a well. In other cases, cementing may be used in remedial operations to repair casing and/or to achieve formation isolation. In still other cases, cementing may be employed during well abandonment.
Cement operations performed in wellbores under high stress conditions may present particular problems, among other things, difficulty in obtaining good wellbore isolation and/or maintaining mechanical integrity of the wellbore over the life of the well. Typical well operations including well production, well testing, and/or hydraulic fracturing operations can produce both radial and tangential stresses in the cemented annulus. The induced stress causes fractures within the cement sheath which lead to fluid intrusion into the wellbore, including intrusion of water, gas, or other fluids. These fractures may also serve as conduits for the intrazonal or interzonal migration of hydrocarbons. Sustained casing pressure and gas charging of shallow potable water zones are but two examples of loss of zonal isolation due to post-cementing stress events.
In a wellbore, cement may be used to serve several purposes. Among these purposes are to selectively isolate particular areas of a wellbore from other areas of the wellbore. For example, cement is commonly placed in the annulus created between the outside surface of a pipe string and the inside formation surface or wall of a wellbore in order to form a sheath to seal off fluid and/or solid production from formations penetrated by the wellbore. This isolation allows a wellbore to be selectively completed to allow production from, or injection into, one or more productive formations penetrated by the wellbore. In other cases cement may be used for purposes including, but not limited to, sealing off perforations, repairing casing leaks (including leaks from damaged areas of the casing), plugging back or sealing off the lower section of a wellbore, sealing the interior of a wellbore during abandonment operations, and so on.
The economic success of a drilling operation often hinges upon the ability to establish zonal isolation within a cemented wellbore. Once established, maintaining this zonal isolation is typically impacted by the particular stress environment found while the well is being completed and produced. During the life of a well, the cement sheath may be exposed to stresses imposed by well operations including perforating, hydraulic fracturing, high temperature-pressure differentials, and so on. Further, if the well is completed using a complex completion such as a multi-lateral system, the cement sheath may be subject to shattering and subsequent loss of bond due to pipe impact.
Conventional well cement compositions are typically brittle when cured. These conventional cement compositions often fail due to stresses, such as radial and/or tangential stresses, that are exerted on the set cement. Wellbore cements may be subjected to radial and tangential stresses that result from a variety of causes. For example, stress conditions may be induced by relatively high temperatures and/or relatively high fluid pressures encountered inside cemented wellbore pipe strings during operations such as perforating, stimulation, injection, testing, production, and so on. Stress conditions may also be induced or aggravated by fluctuations or cycling in temperature or fluid pressures during similar operations. Variations in temperature and internal pressure of the wellbore pipe string may result in radial and longitudinal pipe expansion and/or contraction which tends to place stress on, among other things, the annular cement sheath existing between the outside surface of a pipe string and the inside formation surface or wall of a wellbore. Such stresses may also be induced in cement present in other areas of the wellbore in the pipe.
In other cases, cements placed in wellbores may be subjected to mechanical stress induced by vibrations and impacts resulting from operations, for example, in which wireline and pipe conveyed assembly are moved within the wellbore. Hydraulic, thermal and mechanical stresses may also be induced from forces and changes in forces existing outside the cement sheath surrounding a pipe string. For example, overburden and formation pressures, formation temperatures, formation shifting, formation compaction, etc. may cause stress on cement within a wellbore.
Conventional wellbore cements typically react to excessive stress by failing. “Cement failure” refers to cracking, shattering, debonding from attached surfaces (such as exterior surfaces of a pipe string and/or the wellbore face), or otherwise losing its original properties of strength and/or cohesion. Stress-induced cement failure typically results in loss of formation isolation and/or loss of wellbore mechanical integrity, such as casing collapse or shearing of the casing. This in turn may result in loss of production, loss of the wellbore, pollution, and/or hazardous conditions.
Although hydraulic, thermal and/or mechanical induced stresses may be encountered in all types of wells, including those having conventional vertical wellbores, such stresses may be more likely to occur in particular types of completion configurations. For example, completions having relatively thin annular cement sheaths between pipe strings and/or between the outside surface of a pipe string and the inside formation wall may be particularly susceptible to stress-induced cement damage. Such thin cement sheaths may be encountered, for example, in conditions where open hole wellbore size is limited, yet a cemented pipe string diameter must be maximized. Examples include those cases where so called “slim” well architectures are employed or tieback/scab liners are cemented, for example, to isolate casing damage and/or substantially eliminate formation pressure and/or fluid communication.
In other cases, a main or primary wellbore may have one or more secondary wellbores extending laterally therefrom to form a lateral or multi-lateral completion. In such cases, a primary wellbore may be vertical or deviated (including horizontal), and one or more secondary lateral wells are drilled from the primary wellbore after it has been cased and cemented. Each of the secondary lateral wellbores may be vertical or deviated, and may optionally include a cemented liner, which may be tied into the primary wellbore. In this regard, secondary lateral wellbores may be drilled from a primary wellbore initially, and/or at any other time during the life of the well. Such lateral or multi-lateral completions may be particularly susceptible to stress induced cement failures for a number of reasons. For example, the juncture between the primary and secondary lateral wellbores is typically exposed to mechanical stresses induced by a large number of subsequent operations involving the running of tools through the junction point. The number of operations and exposure to stress typically increases with the number of secondary lateral wellbores extending from the primary wellbore. Furthermore, the magnitude of mechanical stress from a given operation typically increases with the angle of deviation between the axis of the primary wellbore and the a given secondary lateral wellbore.
When conventional cements are employed in lateral or multi-lateral wellbore completions, the set conventional cement is typically too brittle to withstand shocks and impacts generated by drilling and other well operations performed in the secondary lateral wellbores. Therefore, in such completions, conventional set cement compositions typically fail by shattering or cracking, resulting in loss of isolation and mechanical integrity. Potential for such stress-induced cement failure typically increases, for example, in those situations in which the internal diameter of a cased secondary lateral wellbore is designed to be as close as possible to the internal diameter of the cased primary wellbore. This is typically done for ease of drilling and completion, but results in a cement sheath having a reduced thickness, and therefore which is more susceptible to damage.
Similar cement failure problems may be encountered in single wellbores having relatively thin cement sheaths (such as “slimhole” completions), and/or other configurations which cause an increase in the magnitude of frequency of mechanical stresses including wellbores having deviations or doglegs at which mechanical impact may be concentrated. Examples of such wellbores include highly deviated or horizontal completions, and/or sidetracked wellbores.
In other cases, injection or production of high temperature fluids may cause thermal expansion of trapped fluids located, for example, between a pipe string and a cement sheath, between a cement sheath and the formation, and/or within the cement sheath. Such trapped fluids may create excessive pressure differentials when heated and/or cooled, resulting in cement failure. Thermal cycling (such as created by intermittent injection or production of fluids that are very warm or cool relative to the formation temperature), typically increase the likelihood of cement failure.
In still other cases, mechanical and/or hydraulic forces exerted on the exterior of a cement sheath may cause stress-induced cement failure. Such forces include overburden pressures, formation shifting/compaction, and/or exposure to overpressured fluids within a formation. Increased pressure differential, such as may be caused when the interior of a cemented pipe string is partially or completely evacuated of liquid, also tends to promote cement failure, especially when combined with relatively high pressures exerted on the exterior of a cement sheath surrounding the cemented pipe string. Pressure changes may also be the result of natural formation pressure depletion or hydraulic fracturing operations.
In addition, any type of thermal, mechanical or hydraulic stress that acts directly on a set cement composition, or which tends to cause deformation of a wellbore tubular in contact with a set cement composition may promote, or result in, failure of a conventional cement composition.
Furthermore, types of cement configurations that may be adversely affected by stresses, such as those discussed above, include not only annular cement sheaths placed by circulation, but also include cement compositions introduced into a wellbore by a variety of other methods. Such other methods include those employed during or after completion, for example, as part of remedial, workover or abandonment operations. Specific examples include cement placed by squeezing or spotting, to for example, seal off perforations or casing leaks. Presence of high perforation densities may also contribute to cement failure before or after perforation, by explosive force and/or by mechanically weakening a pipe string or tubular so that it is more susceptible to deformation by stress. Such cement configurations may be particularly susceptible to mechanical damage.
The physical properties of set hydraulic cements, including Portland cement, are related to the crystalline structure of the calcium silicate hydrates formed during hydration. Conventional Portland cement reacts with water to form an interlocking crystalline network of various calcium silicate hydrates (CSH), calcium hydroxide (CaOH), calcium sulfo-aluminate and other minor constituents. This interlocking crystalline network provides the compressive strength, tensile strength, and flexural strength of the set cement.
In exploring methods to improve the strength of cement compositions, the civil engineering literature has extensively discussed the presence of interfacial transition zones (ITZ), regions approximately 50 micrometers wide formed around the aggregates in concrete. Essentially, this is a zone having a high porosity that is characterized by a higher CaOH concentration and lower concentrations of CSH than typically found in the matrix of the cement. These porosity structures are commonly viewed to be the “weak link” in concrete regarding its mechanical properties and durability. The micro-structural development of the ITZ is due to the inefficient formation of the hydration products near the aggregate surface and the omni-directional growth effect of the CSH where hydration products are forming from one direction only, in contrast to the matrix of the cement, where hydration products are growing inward from all directions at any given point.
Modifications of the ITZ have been reported with the goal of reducing or eliminating the ITZ. These modifications include reducing the width of the ITZ, or reducing the porosity gradient of the ITZ relative to the bulk material. The addition of silica fume to concrete results in ITZs that are nearly as dense as the bulk paste. This is believed to be due to the small size and reactivity of the silica fume particles allowing packing more closely to the aggregate surface and reducing the one sided growth effect. Similar reductions in the width of the ITZ have been discussed using fly ash and rice husk ash.
Previous work, as is described in U.S. Pat. No. 7,156,173, which is incorporated herein in its entirety, has shown that the ITZ's of individual silica sand particles serve to direct the fracture path within the cement matrix by, in essence, beginning a series of “defects” producing a non-linear fracture pattern within the cement matrix. The fracture itself is in close proximity to, if not in direct contact with, the particle producing the ITZ.
Once fractured however, hydraulic cement has no ability to seal the hydrocarbon flow path that has been created. What is needed is a composition and method of producing a self-sealing cement that minimizes or mitigates the unwanted migration of water or hydrocarbons.